When drilling in deepwater from a floating drilling vessel, a blowout preventer stack (BOP Stack) is typically connected to a wellhead, at the sea floor, and a diverter system, which is mounted under the rig sub-structure at the surface via a marine riser system. Although pressure containing components, connectors, structural members, reentry guidance systems, load bearing components, and control systems have been upgraded for the operational requirement, the overall system architecture has remained common for more than two decades.
The BOP Stack is employed to provide a means to control the well during drilling operations and provide a means to both secure and disconnect from the well in the advent of the vessel losing position due to automatic station keeping failure, weather, sea state, or mooring failure.
A conventionally configured BOP Stack is typically arranged in two sections, including an upper section (Lower Marine Riser Package) which provides an interface to a marine riser via a riser adapter located at the top of the package. The riser adapter is secured to a flex-joint which provides angular movement, e.g. of up to ten degrees (10°), to compensate for vessel offset. The flex-joint assembly, in turn, interfaces with a single or dual element hydraulically operated annular type blowout preventer (BOP), which, by means of the radial element design, allows for the stripping of drill pipe or tubulars which are run in and out of the well. Also located in the Lower Marine Riser Package (or upper section) is a hydraulically actuated connector which interfaces with a mandrel, typically located on the top of the BOP Stack lower section. The BOP Stack lower section typically comprises a series of hydraulically operated ram type BOPs connected together via bolted flanges in a vertical plane creating a ram stack section. In turn, the ram stack section interfaces to a hydraulically latched wellhead connector via a bolted flange. The wellhead connector interfaces to the wellhead, which is a mandrel profile integral to the wellhead housing, which is the conduit to the wellbore.
Conduit lines integral to the marine riser provide for hydraulic fluid supply to the BOP Stack Control System and communication with the wellbore annulus via stack mounted gate valves. The stack mounted gate valves are arranged in the ram stack column at various positions allowing circulation through the BOP Stack column depending on which individual ram is closed.
The unitized BOP Stack is controlled by means of a control system containing pilot and directional control valves which are typically arranged in a control module or pod. Pressure regulators are typically included in the control pod to allow for operating pressure increase/decrease for the hydraulic circuits which control the functions on the unitized BOP Stack. These valves, when commanded from the surface, either hydraulically or electro-hydraulically direct pressurized hydraulic fluid to the function selected. Hydraulic fluid is supplied to the BOP Stack via a specific hydraulic conduit line. In turn, the fluid is stored at pressure in stack-mounted accumulators, which supply the function directional control valves contained in redundant (two (2)) control pods mounted on the lower marine riser package or upper section of the BOP Stack.
Currently, most subsea blowout preventer control systems are arranged with “open” circuitry whereby spent fluid from the particular function is vented to the ocean and not returned to the surface.
A hydraulic power unit and accumulator banks installed within the vessel provide a continuous source of replenishment fluid that is delivered to the subsea BOP Stack mounted accumulators via a hydraulic rigid conduit line and stored at pressure. The development and configuration of BOP Stacks and the control interface for ultra deep water applications has in effect remained conventional as to general arrangement and operating parameters.
Recent deepwater development commitments have placed increased demands for well control systems, requiring dramatic increases in the functional capability of subsea BOP Stacks and, in turn, the control system operating methodologies and complexity. These additional operational requirements and complexities have had a serious effect on system reliability, particularly in the control system components and interface.
Although redundancy provisions are provided by the use of two control pods, a single point failure in either control pod or function interface is considered system failure necessitating securing the well and retrieving the lower marine riser package, containing the control pods, or the complete BOP Stack for repair.
Retrieving any portion of the BOP Stack is time consuming creating “lost revenue” and rig “down time” considering the complete marine riser must be pulled and laid down.
Running and retrieving a subsea BOP Stack in deepwater is a significant event with potential for catastrophic failure and injury risk for personnel involved in the operation.
In addition, vessel configuration, size, capacity, and handling equipment has been dramatically increased to handle, store, and maintain the larger more complex subsea BOP Stacks and equipment. The configuration and pressure rating of the overall BOP Stack requires substantial structural members be incorporated into the assembly design to alleviate bending moment potential, particularly in the choke and kill stab interface area between the Lower Marine Riser Package and BOP Stack interface. These stab interfaces may see in excess of two hundred and seventy five thousand (275,000′) ft/lbs. separating forces, again requiring substantial section modulus in the structural assemblies, which support these components.
Further, a lower marine riser package apron or support assembly size has increased to accommodate the contemporary electro-hydraulic control pods and electronic modules necessary to control and acquire data from an overall Unitized BOP Stack assembly.
Substantial increases in the overall weight and size of high pressure BOP Stacks has created problems for drilling contractors who have a high percentage of existing vessels, which will not accommodate these larger stacks without substantial modifications and considerable expense. In most cases, the larger, heavier and more complex units are requiring by operators for “deep water” applications and reduce the potential for negotiating a contract for the particular rig without this equipment.